table of contents market structure 20 · 2012 quarterly state of the market report for pjm: january...

Table of Contents

2012 Quarterly State of the Market Report for PJM: January through September iii© 2012 Monitoring Analytics, LLC

Table of Contents

Preface i

SECTION 1 Introduction 1Q3 2012 In Review 1PJM Market Background 2Conclusions 3Role of MMU 6

Reporting 7Monitoring 7Market Design 8

Recommendations 8Highlights 10

Section 2, Energy Market 10Section 3, Operating Reserve 11Section 4, Capacity 11Section 5, Demand Response 12Section 6, Net Revenue 12Section 7, Environmental and Renewables 13Section 8, Interchange Transactions 13Section 9, Ancillary Services 14Section 10, Congestion and Marginal Losses 14Section 11, Planning 15Section 12, Financial Transmission Rights and Auction Revenue Rights 15

Total Price of Wholesale Power 15Components of Total Price 15

SECTION 2 Energy Market 17Highlights 17

Conclusion 19

Market Structure 20Supply 20Demand 23Market Concentration 24Local Market Structure and Offer Capping 25Local Market Structure 26Ownership of Marginal Resources 28Type of Marginal Resources 29

Market Conduct: Markup 29Real-Time Mark Up Conduct 30Day-Ahead Mark Up Conduct 30

Market Performance 30Markup 30Real-Time Markup 31Day-Ahead Markup 32Frequently Mitigated Units and Associated Units 34

Market Performance: Load and LMP 36Load 36Locational Marginal Price (LMP) 45Load and Spot Market 62

SECTION 3 Operating Reserve 65Highlights 65Conclusion 65Operating Reserve Credits and Charges 66

Credit and Charge Categories 66Operating Reserve Results 67

Operating Reserve Charges 67Operating Reserve Rates 70Deviations 73Operating Reserve Credits by Category 74

Characteristics of Credits 75Types of Units 75Economic and Noneconomic Generation 77

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Geography of Charges and Credits 78Load Response Resource Operating Reserve Credits 81Reactive Service 82Operating Reserve Issues 83

Concentration of Operating Reserve Credits 83Day-Ahead Unit Commitment for Reliability 85Lost Opportunity Cost Credits 87Black Start and Voltage Support Units 90Up-to Congestion Transactions 91Reactive Service Credits and Operating Reserve Credits 91

SECTION 4 Capacity Market 93Highlights 93Conclusion 94Recommendations 97Installed Capacity 97RPM Capacity Market 98

Market Structure 98Market Conduct 103Market Performance 104

Generator Performance 108Capacity Factor 108Generator Performance Factors 108Generator Forced Outage Rates 109

SECTION 5 Demand-Side Response (DSR) 117Highlights 117

Conclusions 117PJM Demand Side Programs 119Participation in Demand Side Programs 119

Economic Program 120

SECTION 6 Net Revenue 127Highlights 127Net Revenue 127

Theoretical Energy Market Net Revenue 128New Entrant Combustion Turbine 129New Entrant Combined Cycle 129New Entrant Coal Plant 130

SECTION 7 Environmental and Renewable Energy Regulations 133

Highlights 133Conclusion 133Environmental Regulation 134

Federal Control of NOx and SO2 Emissions Allowances 134Federal Environmental Regulation of Greenhouse Gas Emissions 134Federal Environmental Regulation of Reciprocating Internal Combustion Engines (RICE) 135State Regulation of Greenhouse Gas Emissions 136Renewable Portfolio Standards 137

Emissions Controlled Capacity and Renewables in PJM Markets 141Emission Controlled Capacity in the PJM Region 141Wind Units 141Solar Units 144

SECTION 8 Interchange Transactions 145Highlights 145

Conclusion 145Interchange Transaction Activity 146

Aggregate Imports and Exports 146Real-Time Interface Imports and Exports 147Real-Time Interface Pricing Point Imports and Exports 149Day-Ahead Interface Imports and Exports 151Day-Ahead Interface Pricing Point Imports and Exports 154PJM and MISO Interface Prices 162

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2012 Quarterly State of the Market Report for PJM: January through September v© 2012 Monitoring Analytics, LLC

PJM and NYISO Interface Prices 163Summary of Interface Prices between PJM and Organized Markets 165Neptune Underwater Transmission Line to Long Island, New York 165Linden Variable Frequency Transformer (VFT) facility 165

Operating Agreements with Bordering Areas 166PJM and MISO Joint Operating Agreement 166PJM and New York Independent System Operator Joint Operating Agreement (JOA) 167Other Agreements/Protocols with Bordering Areas 167

Interchange Transaction Issues 168Loop Flows 168PJM Transmission Loading Relief Procedures (TLRs) 170Up-To Congestion 171Interface Pricing Agreements with Individual Balancing Authorities 174Willing to Pay Congestion and Not Willing to Pay Congestion 178Spot Imports 178Real-Time Dispatchable Transactions 179

SECTION 9 Ancillary Service Markets 181Highlights 183

Ancillary services costs per MW of load: 2001 - 2012 183Conclusion 183

Regulation Market 184Proposed Market Design Changes 184Market Structure 185Market Conduct 186Market Performance 188

Synchronized Reserve Market 190Market Structure 190Market Conduct 194Market Performance 195

Day Ahead Scheduling Reserve (DASR) 200Market Structure 200Market Conduct 200

Market Performance 201Black Start Service 202

SECTION 10 Congestion and Marginal Losses 203Highlights 203

Conclusion 203Locational Marginal Price (LMP) 204

Components 204Zonal Components 204

Energy Costs 206Energy Accounting 206Total Energy Costs 206

Marginal Losses 207Marginal Loss Accounting 207Total Marginal Loss Costs 208

Congestion 210Congestion Accounting 210Total Congestion 211

Congested Facilities 213Congestion by Facility Type and Voltage 213Constraint Duration 217Constraint Costs 219Congestion-Event Summary for MISO Flowgates 221Congestion-Event Summary for the 500 kV System 223

SECTION 11 Generation and Transmission Planning 225Highlights 225Planned Generation and Retirements 225

Planned Generation Additions 225Planned Deactivations 231Actual Generation Deactivations in 2012 232

Updates on Key Backbone Facilities 234


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SECTION 12 Financial Transmission and Auction Revenue Rights 235

Highlights 236Conclusion 236

Financial Transmission Rights 236Market Structure 237Credit Issues 238Patterns of Ownership 238Market Performance 239

Auction Revenue Rights 252Market Structure 253Market Performance 254

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2012 Quarterly State of the Market Report for PJM: January through September vii© 2012 Monitoring Analytics, LLC

Figures

SECTION 1 IntroductionFigure 1-1 PJM’s footprint and its 19 control zones (See 2011 SOM,

Figure 1-1) 2

SECTION 2 Energy MarketFigure 2-1 Average PJM aggregate supply curves: January through

September, 2011 and 2012 (See 2011 SOM, Figure 2-1) 20Figure 2-2 PJM footprint first nine months peak loads: 2003 to 2012

(See 2011 SOM, Figure 2-2) 23Figure 2-3 PJM peak-load comparison: Tuesday, July 17, 2012, and

Thursday, July 21, 2011 (See 2011 SOM, Figure 2-3) 24Figure 2-4 PJM hourly Energy Market HHI: January through

September 2012 (See 2011 SOM, Figure 2-4) 25Figure 2-5 Frequently mitigated units and associated units

(By month): February, 2006 through September, 2012 (See 2011 SOM, Figure 2-5) 35

Figure 2-6 Frequently mitigated units and associated units total months eligible: February, 2006 through September, 2012 (See 2011 SOM, Figure 2-6) 36

Figure 2-7 PJM real-time accounting load: January through September for years 2011 and 2012 (See 2011 SOM, Figure 2-7) 37

Figure 2-8 PJM real-time monthly average hourly load: 2011 through September of 2012 (See 2011 SOM, Figure 2-8) 38

Figure 2-9 PJM Heating and Cooling Degree Days for January through September for 2011 and 2012 38

Figure 2-10 PJM day-ahead load: January through September for years 2011 and 2012 (See 2011 SOM, Figure 2-9) 39

Figure 2-11 PJM day-ahead monthly average hourly load: 2011 through September of 2012 (See 2011 SOM, Figure 2-10) 40

Figure 2-12 Day-ahead and real-time loads (Average hourly volumes): January through September of 2012 (See 2011 SOM, Figure 2-10) 42

Figure 2-13 Difference between day-ahead and real-time loads (Average daily volumes): January 2011 through September 2012 (See 2011 SOM, Figure 2-12) 42

Figure 2-14 Day-ahead and real-time generation (Average hourly volumes): January through September of 2012 (See 2011 SOM, Figure 2-13) 45

Figure 2-15 Difference between day-ahead and real-time generation (Average daily volumes): January 2011 through September 2012 (See 2011 SOM, Figure 2-14) 45

Figure 2-16 Average LMP for the PJM Real-Time Energy Market: January through September, 2011 and 2012 (See 2011 SOM, Figure 2-15) 46

Figure 2-17 PJM real-time, monthly, load-weighted, average LMP: 2007 through September of 2012 (See 2011 SOM, Figure 2-16) 48

Figure 2-18 Spot average fuel price comparison: 2011 and January through September 2012 ($/MMBtu) (See 2011 SOM, Figure 2-17) 48

Figure 2-19 Average spot fuel cost of generation of CP, CT, and CC: 2011 and January through September 2012 ($/MWh) (New Figure) 49

Figure 2-20 Price for the PJM Day-Ahead Energy Market: January through September, 2011 and 2012 (See 2011 SOM, Figure 2-18) 50

Figure 2-21 Day-ahead, monthly, load-weighted, average LMP: 2007 through September of 2012 (See 2011 SOM, Figure 2-19) 52

Figure 2-22 Hourly volume of bid and cleared INC, DEC and Up-to Congestion bids (MW) by month: January, 2005 through September, 2012 (See 2011 SOM, Figure 2-20) 54

Figure 2-23 PJM day-ahead aggregate supply curves: 2012 example day (See 2011 SOM, Figure 2-21) 58

Figure 2-24 Real-time load-weighted hourly LMP minus day-ahead load-weighted hourly LMP: January through September, 2012 (See 2011 SOM, Figure 2-22) 61

Figure 2-25 Monthly average of real-time minus day-ahead LMP: January through September, 2012 (See 2011 SOM, Figure 2-23) 61


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Figure 2-26 PJM system hourly average LMP: January through September, 2012 (See 2011 SOM, Figure 2-24) 62

SECTION 3 Operating ReserveFigure 3-1 Weekly weighted average day-ahead operating reserve

rate ($/MWh): Calendar years 2011 and 2012 (See 2011 SOM, Figure 3-1) 71

Figure 3-2 Daily balancing operating reserve reliability rates ($/MWh): Calendar years 2011 and 2012 (See 2011 SOM, Figure 3-2) 71

Figure 3-3 Daily balancing operating reserve deviation rates ($/MWh): Calendar years 2011 and 2012 (See 2011 SOM, Figure 3-2) 72

Figure 3-4 Daily lost opportunity cost and canceled resources rates ($/MWh): Calendar years 2011 and 2012 (See 2011 SOM, Figure 3-2) 72

Figure 3-5 Daily average day-ahead generation from units scheduled as must run by PJM: January through September 2012 (New Figure) 86

Figure 3-6 Units scheduled as must run by PJM receiving day-ahead operating reserve credits: January through September 2012 (New Figure) 86

SECTION 4 Capacity MarketFigure 4-1 PJM Locational Deliverability Areas (See the 2011 SOM,

Figure A-3) 100Figure 4-2 PJM RPM EMAAC subzonal LDAs (See the 2011 SOM,

Figure A-4) 100Figure 4-3 History of capacity prices: Calendar year 1999 through

2015 (See the 2011 SOM, Figure 4-1) 107Figure 4-4 PJM equivalent outage and availability factors: Calendar

years 2007 to 2012 (See the 2011 SOM, Table 4-1) 109

Figure 4-5 Trends in the PJM equivalent demand forced outage rate (EFORd): January through September, 2007 to 2012 (See the 2011 SOM, Figure 4-3) 109

Figure 4-6 PJM January through September 2012 distribution of EFORd data by unit type (See the 2011 SOM, Figure 4-4) 110

Figure 4-7 PJM EFORd, XEFORd and EFORp: 2012 (See the 2011 SOM, Figure 4-7) 115

Figure 4-8 PJM monthly generator performance factors: 2012 (See the 2011 SOM, Table 4-8) 116

SECTION 5 Demand-Side Response (DSR)Figure 5-1 Demand Response revenue by market: Calendar years

2002 through 2011 and the first nine months of 2012 (See the 2011 SOM, Figure 5-1) 119

Figure 5-2 Economic Program payments by month: Calendar years 2007 through 2011 and January through September 2012 (See the 2011 SOM, Figure 5-2) 122

SECTION 6 Net RevenueFigure 6-1 Energy Market net revenue factor trends: December

2008 through September 2012 (New Figure) 131

SECTION 7 Environmental and Renewable Energy Regulations

Figure 7-1 Spot monthly average emission price comparison: 2011 and January through September 2012 (See 2011 SOM, Figure 7-1) 137

Figure 7-2 Average hourly real-time generation of wind units in PJM: January through September 2012 (See 2011 SOM, Figure 7-2) 142

Figure 7-3 Average hourly day-ahead generation of wind units in PJM: January through September 2012 (See 2011 SOM, Figure 7-3) 143

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Figure 7-4 Marginal fuel at time of wind generation in PJM: January through September 2012 (See 2011 SOM, Figure 7-4) 144

Figure 7-5 Average hourly real-time generation of solar units in PJM: January through September 2012 (See 2011 SOM, Figure 7-5) 144

SECTION 8 Interchange TransactionsFigure 8-1 PJM real-time and day-ahead scheduled imports and

exports: January through September, 2012 (See 2011 SOM, Figure 8-1) 146

Figure 8-2 PJM real-time and day-ahead scheduled import and export transaction volume history: January 1999, through September 2012 (See 2011 SOM, Figure 8-2) 147

Figure 8-3 PJM’s footprint and its external interfaces (See 2011 SOM, Figure 8-3) 161Figure 8-4 Real-time and day-ahead daily hourly average price

difference (MISO Interface minus PJM/MISO): January through September, 2012 (See 2011 SOM, Figure 8-4) 162

Figure 8-5 Real-time and day-ahead daily hourly average price difference (NY proxy - PJM/NYIS): January through September,

2012 (See 2011 SOM, Figure 8-5) 164Figure 8-6 PJM, NYISO and MISO real-time and day-ahead border

price averages: January through September, 2012 (See 2011 SOM, Figure 8-6) 165

Figure 8-7 Neptune hourly average flow: January through September, 2012 (See 2011 SOM, Figure 8-7) 165

Figure 8-8 Linden hourly average flow: January through September, 2012 (See 2011 SOM, Figure 8-8) 166

Figure 8-9 Credits for coordinated congestion management: January through September, 2012 (See 2011 SOM, Figure 8-9) 167

Figure 8-10 Southwest and southeast actual and scheduled flows: January, 2006 through September, 2012 (See 2011 SOM, Figure 8-10) 170

Figure 8-11 Monthly up-to congestion cleared bids in MWh: January, 2006 through September, 2012 (See 2011 SOM, Figure 8-11) 172

Figure 8-12 Total settlements showing positive, negative and net gains for up-to congestion bids with a matching Real-Time Energy Market transaction (physical) and without a matching Real-Time Energy Market transaction (financial): January through September, 2012 (See 2011 SOM, Figure 8-12) 174

Figure 8-13 Real-time interchange volume vs. average hourly LMP available for Duke and PEC imports: January through September, 2012 (See 2011 SOM, Figure 8-13) 176

Figure 8-14 Real-time interchange volume vs. average hourly LMP available for Duke and PEC exports: January through September, 2012 (See 2011 SOM, Figure 8-14) 176

Figure 8-15 Day-ahead interchange volume vs. average hourly LMP available for Duke and PEC imports: January through September, 2012 (See 2011 SOM, Figure 8-15) 177

Figure 8-16 Day-ahead interchange volume vs. average hourly LMP available for Duke and PEC exports: January through September, 2012 (See 2011 SOM, Figure 8-16) 177

Figure 8-17 Spot import service utilization: January, 2009 through September, 2012 (See 2011 SOM, Figure 8-17) 179

SECTION 9 Ancillary Service MarketsFigure 9-1 PJM Regulation Market HHI distribution: January

through September of 2010, 2011 and 2012 (See 2011 SOM, Figure 9-1) 186

Figure 9-2 Off peak and on peak regulation levels: January through September 2012 (See 2011 SOM, Figure 9-2) 187

Figure 9-3 PJM Regulation Market daily weighted average market-clearing price, marginal unit opportunity cost and offer price (Dollars per MWh): January through September 2012 (See 2011 SOM, Figure 9-3) 188


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Figure 9-4 Monthly average regulation demand and price: January through September 2012 (See 2011 SOM, Figure 9-4) 189

Figure 9-5 Monthly weighted, average regulation cost and price: January through September 2012 (See 2011 SOM, Figure 9-5) 189

Figure 9-6 Ratio of Eligible Synchronized Reserve to Required Tier 2 for all cleared hours in the Mid-Atlantic Subzone: January through September 2012 (See 2011 SOM, Figure 9-6) 191

Figure 9-7 Mid-Atlantic Synchronized Reserve Subzone monthly average synchronized reserve required vs. Tier 2 scheduled MW: January through September 2012 (See 2011 SOM, Figure 9-7) 192

Figure 9-8 RFC Synchronized Reserve Zone, Mid-Atlantic Subzone daily average hourly synchronized reserve required, Tier 2 MW scheduled, and Tier 1 MW estimated: January through September 2012 (See 2011 SOM, Figure 9-9) 192

Figure 9-9 Tier 2 synchronized reserve average hourly offer volume (MW): January through September 2012 (See 2011 SOM, Figure 9-10) 194

Figure 9-10 Average daily Tier 2 synchronized reserve offer by unit type (MW): January through September 2012 (See 2011 SOM, Figure 9-11) 194

Figure 9-11 PJM RFC Zone Tier 2 synchronized reserve scheduled MW: January through September 2012 (See 2011 SOM, Figure 9-12) 195

Figure 9-12 Comparison of Mid-Atlantic Subzone Tier 2 synchronized reserve weighted average price and cost (Dollars per MW): January through September 2012 (See 2011 SOM, Figure 9-16) 196

Figure 9-13 Tier 2 synchronized reserve purchases by month for the Mid-Atlantic Subzone: January through September 2012 (See 2011 SOM, Figure 9-14) 197

Figure 9-14 Impact of Tier 2 synchronized reserve added MW to the RFC Synchronized Reserve Zone, Mid-Atlantic Subzone: January through September 2012 (See 2011 SOM, Figure 9-15) 197

Figure 9-15 Spinning events duration distribution curve, January through September 2009 to 2012 (See 2011 SOM, Figure 9-17) 200

Figure 9-16 Hourly components of DASR clearing price: January through September 2012 (See 2011 SOM, Figure 9-18) 201

SECTION 10 Congestion and Marginal LossesFigure 10-1 PJM monthly congestion (Dollars (Millions)): January

2008 to September 2012 (New Figure) 211Figure 10-2 Location of the top 10 constraints affecting PJM

congestion costs: January through September 2012 (New Figure) 221

SECTION 11 Generation and Transmission PlanningFigure 11-1 Unit retirements in PJM Calendar year 2011 through

2019 (See 2011 SOM, Figure 11-1) 231

SECTION 12 Financial Transmission and Auction Revenue Rights

Figure 12-1 Cleared auction volume (MW) as a percent of total FTR cleared volume by calendar month: June 2004 through September 2012 (See 2011 SOM, Figure 12-2) 242

Figure 12-2 Long Term, Annual and Monthly FTR Auction bid and cleared volume: June 2003 through September 2012 (See 2011 SOM, Figure 12-3) 243

Figure 12-3 Monthly FTR Forfeitures for physical and financial participants: June 2010 through August 2012 (New Figure) 243

Figure 12-4 Ten largest positive and negative revenue producing FTR sinks purchased in the Monthly Balance of Planning Period FTR Auctions: Planning period 2012 to 2013 through September 30, 2012 (See 2011 SOM, Figure 12-11) 246

Figure 12-5 Ten largest positive and negative revenue producing FTR sources purchased in the Monthly Balance of Planning Period FTR Auctions: Planning period 2012 to 2013 through September 30, 2012 (See 2011 SOM, Figure 12-12) 246

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2012 Quarterly State of the Market Report for PJM: January through September xi© 2012 Monitoring Analytics, LLC

Figure 12-6 FTR payout ratio with adjustments by month, excluding and including excess revenue distribution: January 2004 to September 2012 (See 2011 SOM, Figure 12-13) 249

Figure 12-7 Ten largest positive and negative FTR target allocations summed by sink: Planning period 2012 to 2013 through September 30, 2012 (See 2011 SOM, Figure 12-14) 250

Figure 12-8 Ten largest positive and negative FTR target allocations summed by source: Planning period 2012 to 2013 through September 30, 2012 (See 2011 SOM, Figure 12-15) 250

Figure 12-9 FTR Surplus and the collected Day-Ahead, Balancing and Total congestion: January 2005 through September 2012 (New Figure) 251

Figure 12-10 Annual FTR Auction prices vs. average day-ahead and real-time congestion for all control zones relative to the Western Hub: Planning period 2012 to 2013 through September 30, 2012 (See 2011 SOM, Figure 12-16) 255

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2012 Quarterly State of the Market Report for PJM: January through September xiii© 2012 Monitoring Analytics, LLC

Tables

SECTION 1 IntroductionTable 1-1 The Energy Market results were competitive (See 2011

SOM, Table 1-1) 4Table 1-2 The Capacity Market results were competitive (See 2011

SOM, Table 1-2) 4Table 1-3 The Regulation Market results were not competitive (See

2011 SOM, Table 1-3) 5Table 1-4 The Synchronized Reserve Markets results were competitive

(See 2011 SOM, Table 1-4) 5Table 1-5 The Day-Ahead Scheduling Reserve Market results were

competitive (See 2011 SOM, Table 1-5) 6Table 1-6 The FTR Auction Markets results were competitive (see

2011 SOM, Table 1-6) 6Table 1-7 Total price per MWh by category and total revenues by

category: January through September 2011 and 2012 (See 2011 SOM, Table 1-7) 16

SECTION 2 Energy MarketTable 2-1 The Energy Market results were competitive (See 2011

SOM, Table 2-1) 17Table 2-2 PJM generation (By fuel source (GWh)): January through

September 2011 and 2012 (See 2011 SOM, Table 2-2) 21Table 2-3 PJM Generation (By fuel source (GWh)): January through

September 2011 and 2012; excluding ATSI and DEOK zones (See 2011 SOM, Table 2-2) 21

Table 2-4 Distribution of MW for dispatchable unit offer prices: January through September of 2012 (See 2011 SOM, Table 2-3) 22

Table 2-5 Distribution of MW for self-scheduled unit offer prices: January through September of 2012 (See 2011 SOM, Table 2-3) 22

Table 2-6 Actual, PJM footprint peak loads: January through September of 2003 to 2012 (See 2011 SOM, Table 2-4) 23

Table 2-7 PJM hourly Energy Market HHI: January through September 2011 and 2012 (See 2011 SOM, Table 2-5) 24

Table 2-8 PJM hourly Energy Market HHI (By supply segment): January through September 2011 and 2012 (See 2011 SOM, Table 2-6) 25

Table 2-9 Offer-capping statistics: January through September from 2008 to 2012 (See 2011 SOM, Table 2-7) 25

Table 2-10 Real-time offer-capped unit statistics: January through September 2012 (See 2011 SOM, Table 2-8) 26

Table 2-11 Three pivotal supplier results summary for regional constraints: January through September 2012 (See 2011 SOM, Table 2-9) 27

Table 2-12 Three pivotal supplier test details for regional constraints: January through September 2012 (See 2011 SOM, Table 2-10) 27

Table 2-13 Summary of three pivotal supplier tests applied for regional constraints: January through September 2012 (See 2011 SOM, Table 2-11) 28

Table 2-14 Marginal unit contribution to PJM real-time, load-weighted LMP (By parent company): January through September 2012 (See 2011 SOM, Table 2-12) 28

Table 2-15 Marginal unit contribution to PJM day-ahead, load-weighted LMP (By parent company): January through September, 2012 (See 2011 SOM, Table 2-13) 29

Table 2-16 Type of fuel used (By real-time marginal units): January through September, 2012 (See 2011 SOM, Table 2-14) 29

Table 2-17 Day-ahead marginal resources by type/fuel: January through September, 2012 (See 2011 SOM, Table 2-15) 29

Table 2-18 Average, real-time marginal unit markup index (By offer price category): January through September (See 2011 SOM, Table 2-16) 30


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Table 2-19 Average marginal unit markup index (By offer price category): January through September, 2012 (See 2011 SOM, Table 2-17) 30

Table 2-20 Markup component of the overall PJM real-time, load-weighted, average LMP by primary fuel type and unit type: January through September 2012 (See 2011 SOM, Table 2-18) 31

Table 2-21 Monthly markup components of real-time load-weighted LMP: January through September 2012 (See 2011 SOM, Table 2-19) 31

Table 2-22 Average real-time zonal markup component: January through September 2012 (See 2011 SOM, Table 2-20) 32

Table 2-23 Average real-time markup component (By LMP category): January through September 2012 (See 2011 SOM, Table 2-21) 32

Table 2-24 Markup component of the overall PJM day-ahead, load-weighted, average LMP by primary fuel type and unit type: January through September, 2012 (See 2011 SOM, Table 2-22) 33

Table 2-25 Monthly markup components of day-ahead, load-weighted LMP: January through September, 2012 (See 2011 SOM, Table 2-23) 33

Table 2-26 Day-ahead, average, zonal markup component: January through September, 2012 (See 2011 SOM, Table 2-24) 33

Table 2-27 Average, day-ahead markup (By LMP category): January through September, 2012 (See 2011 SOM, Table 2-25) 34

Table 2-28 Number of frequently mitigated units and associated units (By month): January through September, 2012 (See 2011 SOM, Table 2-26) 34

Table 2-29 Frequently mitigated units and associated units total months eligible: January through September, 2011 and 2012 (See 2011 SOM, Table 2-27) 35

Table 2-30 PJM real-time average hourly load: January through September for years 1998 through 2012 (See 2011 SOM, Table 2-28) 37

Table 2-31 PJM annual Summer THI, Winter WWP and average temperature (Degrees F): cooling, heating and shoulder months of 2007 through June of 2012 (See 2011 SOM, Table 2-30) 38

Table 2-32 PJM day-ahead average load: January through September for years 2001 through 2012 (See 2011 SOM, Table 2-31) 40

Table 2-33 Cleared day-ahead and real-time load (MWh): January through September for years 2011 and 2012 (See 2011 SOM, Table 2-32) 41

Table 2-34 PJM real-time average hourly generation: January through September for years 2003 through 2012 (See 2011 SOM, Table 2-33) 43

Table 2-35 PJM day-ahead average hourly generation: January through September for years 2003 through 2012 (See 2011 SOM, Table 2-34) 44

Table 2-36 Day-ahead and real-time generation (MWh): January through September for years 2011 and 2012 (See 2011 SOM, Table 2-35) 44

Table 2-37 PJM real-time, average LMP (Dollars per MWh): January through September, 1998 through 2012 (See 2011 SOM, Table 2-36) 47

Table 2-38 PJM real-time, load-weighted, average LMP (Dollars per MWh): January through September, 1998 through 2012 (See 2011 SOM, Table 2-37) 47

Table 2-39 PJM real-time annual, fuel-cost-adjusted, load-weighted average LMP (Dollars per MWh): Year-over-year method (See 2011 SOM, Table 2-11) 49

Table 2-40 Components of PJM real-time, annual, load-weighted, average LMP: January through September 2012 50

Table 2-41 PJM day-ahead, average LMP (Dollars per MWh): January through September, 2001 through 2012 (See 2011 SOM, Table 2-40) 51

Table 2-42 PJM day-ahead, load-weighted, average LMP (Dollars per MWh): January through September, 2001 through 2012 (See 2011 SOM, Table 2-41) 51

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2012 Quarterly State of the Market Report for PJM: January through September xv© 2012 Monitoring Analytics, LLC

Table 2-43 Components of PJM day-ahead, annual, load-weighted, average LMP (Dollars per MWh): January through September, 2012 (See 2011 SOM, Table 2-42) 52

Table 2-44 Hourly average volume of cleared and submitted INCs, DECs by month: January, 2011 through September, 2012 (See 2011 SOM, Table 2-43) 53

Table 2-45 Hourly average of cleared and submitted up-to congestion bids by month: January, 2011 through September, 2012 (See 2011 SOM, Table 2-44) 54

Table 2-46 Type of day-ahead marginal units: January through September, 2012 (See 2011 SOM, Table 2-45) 54

Table 2-47 PJM INC and DEC bids by type of parent organization (MW): January through September, 2011 and 2012 (See 2011 SOM, Table 2-46) 55

Table 2-48 PJM up-to congestion transactions by type of parent organization (MW): January through September, 2011 and 2012 (See 2011 SOM, Table 2-47) 55

Table 2-49 PJM virtual offers and bids by top ten locations (MW): January through September, 2011 and 2012 (See 2011 SOM, Table 2-48) 56

Table 2-50 PJM cleared up-to congestion import bids by top ten source and sink pairs (MW): January through September, 2011 and 2012 (See 2011 SOM, Table 2-49) 57

Table 2-51 PJM cleared up-to congestion export bids by top ten source and sink pairs (MW): January through September, 2011 and 2012 (See 2011 SOM, Table 2-49) 57

Table 2-52 PJM cleared up-to congestion wheel bids by top ten source and sink pairs (MW): January through September, 2011 and 2012 (See 2011 SOM, Table 2-49) 58

Table 2-53 Day-ahead and real-time average LMP (Dollars per MWh): January through September, 2011 and 2012 (See 2011 SOM, Table 2-50) 59

Table 2-54 Day-ahead and real-time average LMP (Dollars per MWh): January through September, 2001 through 2012 (See 2011 SOM, Table 2-51) 59

Table 2-55 Frequency distribution by hours of PJM real-time and day-ahead load-weighted hourly LMP difference (Dollars per MWh): January through September, 2007 through 2012 (See 2011 SOM, Table 2-52) 60

Table 2-56 Monthly average percentage of real-time self-supply load, bilateral-supply load and spot-supply load based on parent companies: 2011 through 2012 (See 2011 SOM, Table 2-53) 63

Table 2-57 Monthly average percentage of day-ahead self-supply load, bilateral supply load, and spot-supply load based on parent companies: 2011 through 2012 (See 2011 SOM, Table 2-54) 63

SECTION 3 Operating ReserveTable 3-1 Operating reserve credits and charges (See 2011 SOM,

Table 3-1) 67Table 3-2 Operating reserve deviations (See 2011 SOM, Table 3-2) 67Table 3-3 Total operating reserve charges: January through

September 2011 and 2012 (See 2011 SOM, Table 3-6) 67Table 3-4 Monthly operating reserve charges: Calendar years 2011

and 2012 (See 2011 SOM, Table 3-7) 68Table 3-5 Monthly balancing operating reserve charges by category:

Calendar years 2011 and 2012 (See 2011 SOM, Table 3-8) 69Table 3-6 Regional balancing charges allocation: January through

September 2011 (See 2011 SOM, Table 3-9) 70Table 3-7 Regional balancing charges allocation: January through

September 2012 (See 2011 SOM, Table 3-9) 70Table 3-8 Balancing operating reserve rates ($/MWh): January

through September 2011 and 2012 (See 2011 SOM, Table 3-10) 72Table 3-9 Operating reserve rates statistics ($/MWh): January

through September 2012 (See 2011 SOM, Table 3-11) 73Table 3-10 Monthly balancing operating reserve deviations (MWh):

Calendar years 2011 and 2012 (See 2011 SOM, Table 3-3) 74Table 3-11 Regional charges determinants (MWh): January through

September 2012 (See 2011 SOM, Table 3-4) 74


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Table 3-12 Credits by operating reserve category: January through September 2011 and 2012 (See 2011 SOM, Table 3-12) 75

Table 3-13 Credits by unit types (By operating reserve category): January through September 2012 (See 2011 SOM, Table 3-13) 75

Table 3-14 Credits by operating reserve category (By unit type): January through September 2012 (See 2011 SOM, Table 3-14) 76

Table 3-15 Credits by unit type: January through September 2011 and 2012 (New Table) 76

Table 3-16 Credits paid to wind units: Calendar years 2011 and 2012 (See 2011 SOM, Table 3-15) 77

Table 3-17 Day-ahead and real-time generation (GWh): January through September 2012 (New Table) 77Table 3-18 Day-ahead and real-time economic and noneconomic

generation (GWh): January through September 2012 (New Table) 77Table 3-19 Day-ahead and real-time generation receiving operating

reserve credits (GWh): January through September 2012 (New Table) 78

Table 3-20 Geography of charges and credits: January through September 2012 (New Table) 79

Table 3-21 Monthly balancing operating reserve charges and credits to generators (Eastern Region): January through September 2012 (See 2011 SOM, Table 3-17) 80

Table 3-22 Monthly balancing operating reserve charges and credits to generators (Western Region): January through September 2012 (See 2011 SOM, Table 3-18) 80

Table 3-23 Percentage of unit credits and charges of total credits and charges: Calendar years 2011 and 2012 (See 2011 SOM, Table 3-19) 81

Table 3-24 Day-ahead and balancing operating reserve for load response credits: Calendar year 2011 through September 2012 (See 2011 SOM, Table 3-20) 82

Table 3-25 Monthly reactive service credits: Calendar years 2011 and 2012 (See 2011 SOM, Table 3-21) 82

Table 3-26 Reactive service credits by unit type: January through September 2012 (See 2011 SOM, Table 3-22) 83

Table 3-27 Top 10 operating reserve credits units (By percent of total system): Calendar years 2001 through September 2012 (See 2011 SOM, Table 3-23) 83

Table 3-28 Top 10 units and organizations operating reserve credits: January through September 2012 (New Table) 84

Table 3-29 Daily operating reserve credits HHI: January through September 2012 (See 2011 SOM, Table 3-34) 84

Table 3-30 Identification of balancing operating reserve credits received by the top 10 units by category and region: January through September 2012 (See 2011 SOM, Table 3-35) 84

Table 3-31 Average operating reserve rates before and after September 13, 2012 (New Table) 85

Table 3-32 Day-ahead generation from pool-scheduled combustion turbines and engines (GWh): Calendar years 2011 and 2012 (New Table) 88

Table 3-33 Lost opportunity cost credits paid to pool-scheduled combustion turbines and engines by scenario (New Table) 88

Table 3-34 Day-ahead generation (GWh) from pool-scheduled turbines and engines receiving lost opportunity cost credits by value (New Table) 89

Table 3-35 Impact on energy market lost opportunity cost credits of rule changes: January through September 2012 (New Table) 90

Table 3-36 Impact on energy market lost opportunity cost credits of proposed rule changes: January through September 2012 (New Table) 90

Table 3-37 Up-to Congestion Transactions Impact on the Operating Reserve Rates: January through September 2012 (See 2011 SOM, Table 3-44) 91

Table 3-38 Impact of credits paid to units providing reactive services on the balancing operating reserve rates ($/MWh): January through September 2012 (New Table) 92

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2012 Quarterly State of the Market Report for PJM: January through September xvii© 2012 Monitoring Analytics, LLC

SECTION 4 Capacity MarketTable 4-1 The Capacity Market results were competitive (See the

2011 SOM, Table 4-1) 93Table 4-2 RPM Related MMU Reports 96Table 4-3 PJM installed capacity (By fuel source): January 1,

May 31, June 1, and September 30, 2012 (See the 2011 SOM, Table 4-3) 98

Table 4-4 RPM generation capacity additions: 2007/2008 through 2015/2016 (See 2011 SOM, Table 4-5) 98

Table 4-5 RSI results: 2012/2013 through 2015/2016 RPM Auctions (See the 2011 SOM, Table 4-8) 99

Table 4-6 RPM load management statistics by LDA: June 1, 2011 to June 1, 2015, (See the 2011 SOM, Table 4-10) 102

Table 4-7 RPM load management cleared capacity and ILR: 2007/2008 through 2015/2016,, (See the 2011 SOM, Table 4-11) 103

Table 4-8 RPM load management statistics: June 1, 2007 to June 1, 2015, (See the 2011 SOM, Table 4-12) 103

Table 4-9 ACR statistics: Auctions conducted in third quarter, 2012 (See the 2011 SOM, Table 4-14) 104

Table 4-10 Capacity prices: 2007/2008 through 2015/2016 RPM Auctions (See the 2011 SOM, Table 4-21) 105

Table 4-11 RPM revenue by type: 2007/2008 through 2015/2016, (See the 2011 SOM, Table 4-22) 106

Table 4-12 RPM revenue by calendar year: 2007 through 2016 (New Table) 106

Table 4-13 RPM cost to load: 2011/2012 through 2015/2016 RPM Auctions,, (See the 2011 SOM, Table 4-23) 107

Table 4-14 PJM capacity factor (By unit type (GWh)); January through September 2011 and 2012 (See the 2011 SOM, Table 4-24) 108

Table 4-15 PJM EFORd data for different unit types: 2007 to 2012 (See the 2011 SOM, Table 4-25) 110

Table 4-16 OMC Outages: January through September 2012 (See the 2011 SOM, Table 4-30) 112

Table 4-17 PJM EFORd vs. XEFORd: January through September 2012 (See the 2011 SOM, Table 4-31) 113

Table 4-18 Contribution to EFOF by unit type by cause: January through September 2012 (See the 2011 SOM, Table 4-27) 114

Table 4-19 Contributions to Economic Outages: January through September 2012 (See the 2011 SOM, Table 4-28) 114

Table 4-20 PJM EFORd, XEFORd and EFORp data by unit type: January through September 2012 (See the 2011 SOM, Table 4-35) 115

SECTION 5 Demand-Side Response (DSR)Table 5-1 Overview of Demand Side Programs (See the 2011 SOM,

Table 5-1) 119Table 5-2 Economic Program registration on peak load days:

Calendar years 2002 to 2011 and January through September 2012 (See the 2011 SOM, Table 5-2) 120

Table 5-3 Economic Program registrations on the last day of the month: 2008 through September 2012 (See the 2011 SOM, Table 5-3) 120

Table 5-4 Distinct registrations and sites in the Economic Program: July 17, 2012 (See the 2011 SOM, Table 5-4) 121

Table 5-5 Performance of PJM Economic Program participants excluding incentive payments: Calendar years 2002 through 2011 and January through September 2012 (See the 2011 SOM, Table 5-5) 121

Table 5-6 PJM Economic Program participation by zone: January through September 2011 and 2012 (See the 2011 SOM, Table 5-6) 122

Table 5-7 Settlement days submitted by month in the Economic Program: Calendar years 2007 through 2011 and January through September 2012 (See the 2011 SOM, Table 5-7) 123


xviii Table of Contents © 2012 Monitoring Analytics, LLC

Table 5-8 Distinct customers and CSPs submitting settlements in the Economic Program by month: Calendar years 2008 through 2011 and January through September 2012 (See the 2011 SOM, Table 5-8) 123

Table 5-9 Hourly frequency distribution of Economic Program MWh reductions and credits: January through September 2012 (See the 2011 SOM, Table 5-9) 124

Table 5-10 Frequency distribution of Economic Program zonal, load-weighted, average LMP (By hours): January through September 2012 (See the 2011 SOM, Table 5-10) 125

Table 5-11 Zonal monthly capacity credits: January through September 2012 (See the 2011 SOM, Table 5-13) 126

SECTION 6 Net RevenueTable 6-1 Energy Market net revenue for a new entrant gas-fired

CT under economic dispatch (Dollars per installed MW-year) (See the 2011 SOM, Table 6-3) 129

Table 6-2 PJM Energy Market net revenue for a new entrant gas-fired CC under economic dispatch (Dollars per installed MW-year) (See the 2011 SOM, Table 6-6) 130

Table 6-3 PJM Energy Market net revenue for a new entrant CP under economic dispatch (Dollars per installed MW-year) (See the 2011 SOM, Table 6-9) 130

SECTION 7 Environmental and Renewable Energy Regulations

Table 7-1 RGGI CO2 allowance auction prices and quantities: 2009-2011 and 2012-2014 Compliance Periods (See 2011 SOM, Table 7-3) 136

Table 7-2 Renewable standards of PJM jurisdictions to 2022, (See 2011 SOM, Table 7-4) 138

Table 7-3 Solar renewable standards of PJM jurisdictions to 2022 (See 2011 SOM Table 7-5) 138

Table 7-4 Renewable generation by jurisdiction and renewable resource type (GWh): January through September 2012 (See 2011 SOM, Table 7-8) 139

Table 7-5 PJM renewable capacity by jurisdiction (MW), on September 30, 2012 (See 2011 SOM, Table 7-9) 140

Table 7-6 Renewable capacity by jurisdiction, non-PJM units registered in GATS, (MW), on September 30, 2012 (See 2011 SOM, Table 7-10) 140

Table 7-7 SO2 emission controls (FGD) by unit type (MW), as of September 30, 2012 (See 2011 SOM, Table 7-11) 141

Table 7-8 NOx emission controls by unit type (MW), as of September 30, 2012 (See 2011 SOM, Table 7-12) 141

Table 7-9 Particulate emission controls by unit type (MW), as of September 30, 2012 (See 2011 SOM, Table 7-13) 141

Table 7-10 Capacity factor of wind units in PJM, January through September 2012 (See 2011 SOM, Table 7-14) 142

Table 7-11 Wind resources in real time offering at a negative price in PJM, January through September 2012 (See 2011 SOM, Table 7-15) 142

Table 7-12 Capacity factor of wind units in PJM by month, 2011 and 2012 (See 2011 SOM, Table 7-16) 143

SECTION 8 Interchange TransactionsTable 8-1 Real-time scheduled net interchange volume by interface

(GWh): January through September, 2012 (See 2011 SOM, Table 8-1) 148

Table 8-2 Real-time scheduled gross import volume by interface (GWh): January through September, 2012 (See 2011 SOM,

Table 8-2) 148Table 8-3 Real-time scheduled gross export volume by interface

(GWh): January through September, 2012 (See 2011 SOM, Table 8-3) 149

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2012 Quarterly State of the Market Report for PJM: January through September xix© 2012 Monitoring Analytics, LLC

Table 8-4 Real-time scheduled net interchange volume by interface pricing point (GWh): January through September, 2012 (See 2011 SOM, Table 8-4) 150

Table 8-5 Real-time scheduled gross import volume by interface pricing point (GWh): January through September, 2012 (See 2011 SOM, Table 8-5) 151

Table 8-6 Real-time scheduled gross export volume by interface pricing point (GWh): January through September, 2012 (See 2011 SOM, Table 8-6) 151

Table 8-7 Day-Ahead scheduled net interchange volume by interface (GWh): January through September, 2012 (See 2011 SOM, Table 8-7) 152

Table 8-8 Day-Ahead scheduled gross import volume by interface (GWh): January through September, 2012 (See 2011 SOM, Table 8-8) 153

Table 8-9 Day-Ahead scheduled gross export volume by interface (GWh): January through September, 2012 (See 2011 SOM, Table 8-9) 154

Table 8-10 Day-Ahead scheduled net interchange volume by interface pricing point (GWh): January through September, 2012 (See 2011 SOM, Table 8-10) 155

Table 8-11 Up-to Congestion scheduled net interchange volume by interface pricing point (GWh): January through September, 2012 (New Table) 156

Table 8-12 Day-Ahead scheduled gross import volume by interface pricing point (GWh): January through September, 2012 (See 2011 SOM, Table 8-11) 157

Table 8-13 Up-to Congestion scheduled gross import volume by interface pricing point (GWh): January through September, 2012 (New Table) 158

Table 8-14 Day-Ahead scheduled gross export volume by interface pricing point (GWh): January through September, 2012 (See 2011 SOM, Table 8-12) 159

Table 8-15 Up-to Congestion scheduled gross export volume by interface pricing point (GWh): January through September, 2012 (New Table) 160

Table 8-16 Active interfaces: January through September, 2012 (See 2011 SOM, Table 8-13) 161

Table 8-17 Active pricing points: January through September, 2012 (See 2011 SOM, Table 8-14) 161

Table 8-18 Distribution of economic and uneconomic hourly flows between PJM and MISO: January through September, 2012 (New Table) 163

Table 8-19 Distribution of economic and uneconomic hourly flows between PJM and NYISO: January through September, 2012 (New Table) 164

Table 8-20 Con Edison and PSE&G wheeling agreement data: January through September, 2012 (See 2011 SOM, Table 8-15) 168

Table 8-21 Net scheduled and actual PJM flows by interface (GWh): January through September, 2012 (See 2011 SOM, Table 8-16) 169

Table 8-22 Net scheduled and actual PJM flows by interface pricing point (GWh): January through September, 2012 (See 2011 SOM, Table 8-17) 170

Table 8-23 PJM and MISO TLR procedures: January, 2010 through September, 2012 (See 2011 SOM, Table 8-19) 171

Table 8-24 Number of TLRs by TLR level by reliability coordinator: January through September, 2012 (See 2011 SOM, Table 8-18) 171

Table 8-25 Monthly volume of cleared and submitted up-to congestion bids: January, 2009 through September, 2012 (See 2011 SOM, Table 8-20) 173

Table 8-26 Real-time average hourly LMP comparison for southeast, southwest, SouthIMP and SouthEXP interface pricing points: January through September, 2007 through 2012 (See 2011 SOM, Table 8-21) 175

Table 8-27 Real-time average hourly LMP comparison for Duke, PEC and NCMPA: January through September, 2012 (See 2011 SOM, Table 8-22) 175


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Table 8-28 Day-ahead average hourly LMP comparison for southeast, southwest, SouthIMP and SouthEXP Interface pricing points: January through September, 2007 through 2012 (See 2011 SOM, Table 8-23) 177

Table 8-29 Day-ahead average hourly LMP comparison for Duke, PEC and NCMPA: January through September, 2012 (See 2011 SOM, Table 8-24) 177

Table 8-30 Monthly uncollected congestion charges: Calendar years 2010 and 2011 and January through September, 2012 (See 2011 SOM, Table 8-25) 178

SECTION 9 Ancillary Service MarketsTable 9-1 The Regulation Market results were not competitive

(See 2011 SOM, Table 9-1) 181Table 9-2 The Synchronized Reserve Markets results were

competitive (See 2011 SOM, Table 9-2) 182

Table 9-3 The Day-Ahead Scheduling Reserve Market results were competitive (See 2011 SOM, Table 9-3) 182

Table 9-4 History of ancillary services costs per MW of Load: January through September, 2001 through 2012 (See 2011 SOM, Table 9-4) 183

Table 9-5 PJM regulation capability, daily offer and hourly eligible: January through September 2012 (See 2011 SOM, Table 9-5) 185

Table 9-6 Impact on PJM Regulation Market of currently regulating units scheduled to retire through 2015 (New Table) 185

Table 9-7 PJM Regulation Market required MW and ratio of eligible supply to requirement: January through September 2012 and 2011 (See 2011 SOM, Table 9-6) 185

Table 9-8 PJM cleared regulation HHI: January through September 2012 and 2011 (See 2011 SOM, Table 9-7) 186

Table 9-9 Regulation market monthly three pivotal supplier results: January through September 2010, 2011 and 2012 (See 2011 SOM, Table 9-9) 186

Table 9-10 Regulation sources: spot market, self-scheduled, bilateral purchases: January through September 2012 (See 2011 SOM, Table 9-10) 187

Table 9-11 PJM Regulation Market monthly weighted average market-clearing price, marginal unit opportunity cost and offer price (Dollars per MWh): January through September 2012 (New Table) 189

Table 9-12 Total regulation charges: January through September 2012 (See 2011 SOM, Table 9-11) 190

Table 9-13 Comparison of average price and cost for PJM Regulation, January through September 2006 through 2012 (See 2011 SOM, Table 9-12) 190

Table 9-14 Synchronized Reserve Market required MW, RFC Zone and Mid-Atlantic Subzone, December 2008 through September 2012 (See 2011 SOM, Table 9-16) 191

Table 9-15 Synchronized Reserve market monthly three pivotal supplier results: January through September 2011 and 2012 (See 2011 SOM, Table 9-9) 193

Table 9-16 Average RFC SRMCP when all cleared synchronized reserve is DSR, average SRMCP, and percent of all cleared hours that all cleared synchronized reserve is DSR: January through September 2010, 2011, 2012 (See 2011 SOM, Table 9-18) 195

Table 9-17 Comparison of weighted average price and cost for PJM Synchronized Reserve, January through September, 2005 through 2012 (See 2011 SOM, Table 9-19) 196

Table 9-18 Tier 1 bias used by PJM Dispatch January through September, 2008 through 2012 (New Table) 198

Table 9-19 Spinning Events, January 2009 through September 2012 (See 2011 SOM, Table 9-20) 199

Table 9-20 PJM Day-Ahead Scheduling Reserve Market MW and clearing prices: January through September 2011 and 2012 (See 2011 SOM, Table 9-21) 201

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2012 Quarterly State of the Market Report for PJM: January through September xxi© 2012 Monitoring Analytics, LLC

Table 9-21 Black start yearly zonal charges for network transmission use: January through September 2012 (See 2011 SOM, Table 9-22) 202

SECTION 10 Congestion and Marginal LossesTable 10-1 PJM real-time, load-weighted average LMP components

(Dollars per MWh): January through September, 2009 through 2012 (See 2011 SOM, Table 10-1) 204

Table 10-2 PJM day-ahead, load-weighted average LMP components (Dollars per MWh): January through September, 2009 through 2012 (See 2011 SOM, Table 10-2) 204

Table 10-3 Zonal and PJM real-time, load-weighted average LMP components (Dollars per MWh): January through September, 2011 and 2012 (See 2011 SOM, Table 10-3) 205

Table 10-4 Zonal and PJM day-ahead, load-weighted average LMP components (Dollars per MWh): January through September, 2011 and 2012 (See 2011 SOM, Table 10-4) 206

Table 10-5 Total PJM costs by component (Dollars (Millions)): January through September, 2009 through 2012 (See 2011 SOM, Table 10-5) 207

Table 10-6 Total PJM energy costs by category (Dollars (Millions)): January through September, 2009 through 2012 (See 2011 SOM, Table 10-6) 207

Table 10-7 Total PJM energy costs by market category (Dollars (Millions)): January through September, 2009 through 2012 (See 2011 SOM, Table 10-7) 207

Table 10-8 Monthly energy costs by type (Dollars (Millions)): January through September, 2011 and 2012 (See 2011 SOM, Table 10-8) 207

Table 10-9 Total PJM Marginal Loss Costs (Dollars (Millions)): January through September, 2009 through 2012 (See 2011 SOM, Table 10-9) 208

Table 10-10 Total PJM marginal loss costs by category (Dollars (Millions)): January through September, 2009 through 2012 (See 2011 SOM, Table 10-10) 208

Table 10-11 Total PJM marginal loss costs by market category (Dollars (Millions)): January through September, 2009 through 2012 (See 2011 SOM, Table 10-11) 209

Table 10-12 Monthly marginal loss costs by type (Dollars (Millions)): January through September, 2011 and 2012 (See 2011 SOM, Table 10-12) 209

Table 10-13 Marginal loss credits (Dollars (Millions)): January through September, 2009 through 2012 (See 2011 SOM, Table 10-13) 209

Table 10-14 Total PJM congestion (Dollars (Millions)): January through September for calendar years 2008 to 2012 (See 2011 SOM, Table 10-14) 211

Table 10-15 Total PJM congestion costs by category (Dollars (Millions)): January through September, 2011 and 2012 (See 2011 SOM, Table 10-15) 212

Table 10-16 Total PJM congestion costs by market category (Dollars (Millions)): January through September, 2011 and 2012 (See 2011 SOM, Table 10-16) 212

Table 10-17 Monthly PJM congestion costs (Dollars (Millions)): January through September 2012 (See 2011 SOM, Table 10-17) 212

Table 10-18 Monthly PJM congestion costs (Dollars (Millions)): January through September 2011 (See 2011 SOM, Table 10-18) 213

Table 10-19 Congestion summary (By facility type): January through September 2012 (See 2011 SOM, Table 10-19) 214

Table 10-20 Congestion summary (By facility type): January through September 2011 (See 2011 SOM, Table 10-20) 214

Table 10-21 Congestion Event Hours (Day Ahead against Real Time): January through September 2011 and 2012 (See 2011 SOM, Table 10-21) 215

Table 10-22 Congestion Event Hours (Real Time against Day Ahead): January through September 2011 and 2012 (See 2011 SOM, Table 10-22) 215


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Table 10-23 Congestion summary (By facility voltage): January through September 2012 (See 2011 SOM, Table 10-23) 216

Table 10-24 Congestion summary (By facility voltage): January through September 2011 (See 2011 SOM, Table 10-24) 216

Table 10-25 Top 25 constraints with frequent occurrence: January through September 2011 and 2012 (See 2011 SOM, Table 10-25) 217

Table 10-26 Top 25 constraints with largest year-to-year change in occurrence: January through September 2011 and 2012 (See 2011 SOM, Table 10-26) 218

Table 10-27 Top 25 constraints affecting PJM congestion costs (By facility): January through September 2012 (See 2011 SOM, Table 10-27) 219

Table 10-28 Top 25 constraints affecting PJM congestion costs (By facility): January through September 2011 (See 2011 SOM, Table 10-28) 220

Table 10-29 Top congestion cost impacts from MISO flowgates affecting PJM dispatch (By facility): January through September 2012 (See 2011 SOM, Table 10-29) 222

Table 10-30 Top congestion cost impacts from MISO flowgates affecting PJM dispatch (By facility): January through September 2011 (See 2011 SOM, Table 10-30) 223

Table 10-31 Regional constraints summary (By facility): January through September 2012 (See 2011 SOM, Table 10-31) 224

Table 10-32 Regional constraints summary (By facility): January through September 2011 (See 2011 SOM, Table 10-32) 224

SECTION 11 Generation and Transmission PlanningTable 11-1 Year-to-year capacity additions from PJM generation

queue: Calendar years 2000 through September 30, 2012 (See 2011 SOM, Table 11-1) 225

Table 11-2 Queue comparison (MW): September 30, 2012 vs. December 31, 2011 (See 2011 SOM, Table 11-3) 226

Table 11-3 Capacity in PJM queues (MW): At September 30, 2012, (See 2011 SOM, Table 11-4) 226

Table 11-4 Average project queue times (days): At September 30, 2012 (See 2011 SOM, Table 11-5) 227

Table 11-5 Active capacity queued to be in service prior to October 1, 2012 (New table) 227

Table 11-6 Capacity additions in active or under-construction queues by control zone (MW): At September 30, 2012 (See 2011 SOM, Table 11-6) 228

Table 11-7 Capacity additions in active or under-construction queues by LDA (MW): At September 30, 2012 (See 2011 SOM, Table 11-7) 228

Table 11-8 Existing PJM capacity: At September 30, 2012 (By zone and unit type (MW)) (See 2011 SOM, Table 11-8) 229

Table 11-9 PJM capacity (MW) by age: at September 30, 2012 (See 2011 SOM Table 11-9) 229

Table 11-10 Comparison of generators 40 years and older with slated capacity additions (MW): Through 2018 (See 2011 SOM, Table 11-10) 230

Table 11-11 Summary of PJM unit retirements (MW): Calendar year 2011 through 2019 (See 2011 SOM, Table 11-11) 231

Table 11-12 Planned deactivations of PJM units in calendar year 2012 as of October 1, 2012 (See 2011 SOM, Table 11-12) 231

Table 11-13 Planned deactivations of PJM units after calendar year 2012, as of October 1, 2012 (See 2011 SOM, Table 11-13) 232

Table 11-14 HEDD Units in PJM as of October 1, 2012 (See 2011 SOM, Table 11-14) 232

Table 11-15 Unit deactivations: January through October 1, 2012 (See 2011 SOM, Table 11-15) 233

SECTION 12 Financial Transmission and Auction Revenue Rights

Table 12-1 The FTR Auction Markets results were competitive (See 2011 SOM, Table 12-1) 235

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2012 Quarterly State of the Market Report for PJM: January through September xxiii© 2012 Monitoring Analytics, LLC

Table 12-2 Monthly Balance of Planning Period FTR Auction patterns of ownership by FTR direction: January through September 2012 (See 2011 SOM, Table 12-6) 238

Table 12-3 Daily FTR net position ownership by FTR direction: January through September 2012 (See 2011 SOM, Table 12-7) 239

Table 12-4 Monthly Balance of Planning Period FTR Auction market volume: January through September 2012 (See 2011 SOM, Table 12-11) 240

Table 12-5 Monthly Balance of Planning Period FTR Auction buy-bid, bid and cleared volume (MW per period): January through September 2012 (See 2011 SOM, Table 12-12) 241

Table 12-6 Secondary bilateral FTR market volume: Planning periods 2011 to 2012 and 2012 to 2013 (See 2011 SOM, Table 12-13) 242

Table 12-7 Monthly Balance of Planning Period FTR Auction cleared, weighted-average, buy-bid price per period (Dollars per MW): January through September 2012 (See 2011 SOM, Table 12-16) 244

Table 12-8 Monthly Balance of Planning Period FTR Auction revenue: January through September 2012 (See 2011 SOM, Table 12-20) 245

Table 12-9 Total annual PJM FTR revenue detail (Dollars (Millions)): Planning periods 2011 to 2012 and 2012 to 2013 (See 2011 SOM, Table 12-21) 248

Table 12-10 Monthly FTR accounting summary (Dollars (Millions)): Planning periods 2011 to 2012 and 2012 to 2013 (See 2011 SOM, Table 12-22) 248

Table 12-11 FTR payout ratio by planning period (See 2011 SOM, Table 12-23) 249

Table 12-12 FTR profits by organization type and FTR direction: January through September 2012 (See 2011 SOM, Table 12-24) 251

Table 12-13 Monthly FTR profits by organization type: January through September 2012 (See 2011 SOM, Table 12-25) 252

Table 12-14 Residual ARR allocation volume and target allocation (New Table) 253

Table 12-15 ARRs and ARR revenue automatically reassigned for network load changes by control zone: June 1, 2011, through September 30, 2012 (See 2011 SOM, Table 12-29) 254

Table 12-16 ARR revenue adequacy (Dollars (Millions)): Planning periods 2011 to 2012 and 2012 to 2013 (See 2011 SOM, Table 12-33) 254

Table 12-17 ARR and self-scheduled FTR congestion offset (in millions) by control zone: Planning period 2012 to 2013 through September 30, 2012 (See 2011 SOM, Table 12-34) 256

Table 12-18 ARR and FTR congestion offset (in millions) by control zone: Planning period 2012 to 2013 through September 30, 2012 (See 2011 SOM, Table 12-35) 257

Table 12-19 ARR and FTR congestion hedging (in millions): Planning periods 2011 to 2012 and 2012 to 2013 through September 30, 2012 (See 2011 SOM, Table 12-36) 257

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